SOx capture using carbonate absorbent

ABSTRACT

A desulfurization gas process includes water vapor, CO2 and SOx (x=2 and/or 3). In a treatment unit, the gas contacts a cooled alkaline aqueous solution having a temperature lower than an initial gas temperature, water and a carbonate of an alkali metal, to cool the gas, condense some water vapor and absorb SOx in the carbonate-containing solution, produce an SOx-depleted gas and an acidic aqueous solution including sulfate and/or sulfite ions. The SOx-depleted gas and a portion of the acidic aqueous solution can then be withdrawn from the treatment unit. Carbonate of the alkali metal can be added to remaining acidic aqueous solution to obtain a made-up alkaline aqueous solution. This solution can be cooled and reused as the cooled alkaline aqueous solution. An SOx absorbent solution includes a bleed stream from a CO2-capture process, sodium or potassium carbonate, and an acidic aqueous solution obtained from desulfurization.

RELATED APPLICATION

This application is a National Stage Application of PCT/CA2018/050968filed on Aug. 10, 2018, which claims priority to U.S. provisionalapplication No. 62/544,382 filed on Aug. 11, 2017, the contents of whichare incorporated herein by reference in their entireties. To the extentappropriate, a claim of priority is made to each of the above-disclosedapplications.

TECHNICAL FIELD

The technical field generally relates to processes and systems for thecapture of SO₂ and or SO₃ from gases that are produced by variousindustrial processes, using carbonate absorbent. The technical fieldalso relates to processes and systems for the capture of SO₂ and/or SO₃from CO₂-containing gases to be further treated for CO₂ removal, such asfrom flue gases after the combustion of carbon-based fuels.

BACKGROUND

Gases produced by industrial processes, such as post-combustion fluegases, generally comprise water vapour (H₂O), carbon dioxide (CO₂),nitrogen (N₂) and oxygen (O₂), and may also comprise some othercompounds such as acid gases SO_(x), NO_(x), H₂S, depending on theprocess from which the flue gas originates. “SO_(x)” refers to SO₂ andSO₃, and NO_(x) refers to NO and NO₂. These acid gases are chemicallyabsorbed when contacted with alkaline absorption solutions commonly usedin CO₂ capture systems.

CO₂ capture can generally refer to processes such as CO₂ absorption andstripping for pure CO₂ production, CO₂ removal from gases, CO₂ pressureswing adsorption, and others. CO₂ utilization may comprise CO₂transformation into carbonate based compounds, use for algae growth,biofuel applications in fuel cells, such as molten carbonate fuel cells(MCFC).

For numerous post-combustion CO₂ capture processes, when the flue gas tobe treated contains SO_(x) in addition to CO₂, the flue gas is first tobe treated to reduce its SO_(x) concentration below a threshold value toavoid adverse impact (e.g., reaction, precipitation, inhibition) whichmay occur in contact with the absorption solution or the adsorbent, asthe case may be, that could result in a decrease of the absorptionsolution or adsorbent capacity. Conventional SO_(x) removal technologiesare used for such a purpose.

These conventional SO_(x) removal technologies can be classified asonce-through or regenerable, and both comprise wet or dry processes. Theonce-through wet technologies use limestone, lime, magnesium-enhancedlime or sea water. Technologies consisting of a dry process involve limespray drying, duct sorbent injection, furnace solvent injection andcirculating fluidized bed. Regenerable wet technologies are based on theuse of sodium sulfite, magnesium oxide, sodium carbonate and amine; andregenerable dry processes are based on activated carbon. Suchtechnologies are detailed in Srivastava, R. K., Controlling SO ₂Emission: A review of Technologies, Report EPA/600/R-00/093, November2000, 113 pages.

These technologies have been implemented as an auxiliary unit to the CO₂capture or CO₂ utilization process and there has been no integrationbetween both processes (SO_(x) removal and CO₂ capture and/or CO₂utilization).

In a CO₂ capture process using an alkaline potassium carbonate solutionas the absorbing media, SO_(x) and NO_(x) will be absorbed in thealkaline absorption solution and react with the potassium ions resultingin a loss of the absorption solution capacity and the formation of saltprecipitates above a specific threshold concentration. To avoid suchefficiency losses or precipitation, SO_(x) and NO_(x) levels in theabsorption cycle are controlled by bleeding solution from the mainabsorption loop. In order to reduce the bleed rate required, SO_(x) orNO_(x) contaminants are removed from the flue gas before the mainabsorption process in a gas conditioning step which also sets the gasinlet temperature for the absorbing process, in a direct or indirectcontact unit. In addition, CO₂ capture processes can generate wastesassociated with the degradation of the absorption solution. For example,in the case of a CO₂ capture process that uses amines, such asmonoethanolamine (MEA), a side-reaction produces a heat-stable salts asundesirable by-products that need to be disposed of.

Even though the SO_(x) levels are considerably reduced in the gasconditioning step, the residual quantity of the contaminants will beabsorbed into the alkaline absorption solutions used for CO₂ capture andwill accumulate, eventually resulting in a precipitate, which willconsume some of the cations away from the carbonate and reduce thesolution's absorption capacity. To compensate for these two impacts,part of the absorption solution is bled off to reduce the circulatingsolution's concentration in sulfate, nitrite and nitrate ions, and thebled off solution is replaced with a fresh carbonate solution. Thesolution bleed is then disposed of using normal health, safety andenvironmental practices. This bleeding and replenishment strategy isused in conventional CO₂ capture processes using amines as absorptioncompounds. A CO₂ capture process using this common strategy isillustrated in FIG. 1.

Referring to FIG. 1, a flue gas (1) is first cooled down in a coolingunit (2) using a water feed (3). Heated water (4) then leaves thecooling unit. The cooled flue gas is then sent to a CO₂ absorption unit(6) where CO₂ and other acid gases, such as SO_(x) and NO_(x) areabsorbed in an absorption solution that flows through the absorptionunit (6). The treated CO₂-depleted gas is then released to theatmosphere (7). The absorption solution containing the absorbed CO₂,SO_(x) and NO_(x) (8) is heated using a heat exchanger (9) and then sentto a stripping unit (11) where the CO₂ is desorbed from the solutionusing temperature and/or pressure swing conditions and released as arecovered CO₂ stream (12) for further processing. The absorptionsolution leaving the stripping unit, which can be referred to as aregenerated absorption solution (10), is lean in CO₂. However, thelean-absorption solution (10) still contains ions coming from thereactions of SO_(x) and NO_(x) in the absorption solution. These ionswill accumulate in the absorption solution over time as it circulatesthrough the absorption unit (6) and the stripping unit (11). In order tocontrol their concentration levels in the absorption solution, a volumeof the solution is removed as absorption solution bleed stream (13) andreplaced with fresh solution (14). In the case of an absorption solutionbased on the use of carbonates as absorption compounds, such as the UNOMK3 process, SO_(x) and NO_(x) are recovered as KNO₃ and K₂SO₄ solids inthe process and removed from the absorption solution using ahydrocyclone.

The impact of SO_(x) and NO_(x) on the performance of CO₂ captureprocesses is explained in further detail as follows. SO₂ reacts inaqueous media to form a proton and a bisulfite ion (Equation 1). In anaqueous solution, the bisulfite ion is in equilibrium with a sulfite ionand a proton (Equation 2). SO₃ gas reacts with water to form sulphuricacid (Equation 3). In the presence of oxygen, sulfite ions are oxidizedto sulfate ions (Equation 4). Sulfate ions are susceptible toprecipitation in carbonate absorption solutions, such as a potassiumcarbonate solution. Precipitation of the K₂SO₄ salt may reduceperformance or jeopardize the CO₂ capture process. Additionally, the K⁺that reacts to form K₂SO₄ can no longer be used in the capture of CO₂,thus reducing the absorption capacity of the solution.SO_(2(g))+H₂O↔HSO₃ ⁻+H⁺  Equation 1HSO₃ ⁻↔H⁺+SO₃ ²⁻  Equation 2SO^(3(g))+H₂O ↔H₂SO₄  Equation 3HSO₃ ⁻+0.5O₂↔SO₄ ²⁻+H⁺  Equation 4.

In general, there is typically much more SO₂ in the gas compared to SO₃,and therefore Equations 1 and 2 typically dominate.

NO_(x) are also combustion by-products that may be present in flue gasesin various ratios. NO_(x) can be absorbed by the absorption solution andtransformed into nitrite/nitrate ions in solution as shown in Equation5, 6 and 7.NO_((g))+NO_(2(g))+H₂O↔2NO₂ ⁻+2H⁺  Equation 52NO_(2(g))+H₂O↔NO₂ ⁻+NO₃ ⁻+2H⁺  Equation 62NO₂+SO₃ ²⁻+H₂O→2H⁺+2NO₂ ⁻+SO₄ ²⁻  Equation 7.

A certain percentage of NO_(x) may be irreversibly absorbed by theabsorption solution and accumulates as a salt. As for SO_(x), thisaccumulation may incur an absorption solution loss which results in adecrease CO₂ capture capacity. Each contaminant (SO_(x) and NO_(x)) hasa different rate of reaction with the absorption solution. SO₂, the mainSO_(x) constituent, is much more soluble in aqueous solution than NO andNO₂. The Henry constant (in water at 25° C.) for SO₂ is 1.2 M/atm whilethis constant is at 0.0019 and 0.041 for NO and NO₂ respectively (DurhamJ. L. et al., Influence of gaseous nitric acid on sulfate production andacidity in rain, Atmos. Environ., 15, 1059-1068, 1981). The kinetics ofSO₂ reaction with water is very fast and is considered as instantaneous(Ryuichi Kaji et al., Journal of Chemical Engineering of Japan, Vol. 18(1985) No. 2, p. 169-172). Another reference in this field is Sander,R., Compilation of Henry's Law Constants for Inorganic and OrganicSpecies of Potential Importance in Environmental Chemistry, Version 3,1999, Max-Planck Institute of Chemistry, Germany. The kinetics for theNO_(x) reactions are far slower. The fact that the NO_(x) molecules needto react with themselves before reacting with water (see Equations 5 and6) combined with the fact that their concentrations in water are verylow makes those reactions much slower. This is exemplified in thedocument “Cost and Performance Baseline for Fossil Energy Plants” Volume1a: Bituminous Coal (PC) and Natural Gas to Electricity Revision 3,2015, DOENETL-2015/1723, p. 76 and p. 98, describing the effect of a CO₂capture unit (based on the CANSOLV technology) on the emission of SO_(x)and NO_(x) from a pulverized coal power plant. In the case B11 describedin this document, the unit reduced the total SO_(x) emissions of thepower plant from 0.318 kg/MWh to zero. This same unit has no effect onNO_(x) emissions.

As mentioned above, conventional ways to manage impurities in CO₂capture processes would be to maintain an adequate SO₄ ²⁻ concentrationlevel below the concentration leading sulfate salt precipitation, whichmay be done by bleeding and disposing of a portion of the absorptionsolution and replacing it by an equivalent volume of fresh solution.However, as explained above, the absorption and reaction of SO_(x) isfaster and more complete than for NO_(x), resulting is an absorptionsolution having a SO₄ ⁻² ion concentration close to the precipitationthreshold concentration, whereas the concentration of NO_(x) specieswould be much lower than the precipitation threshold concentration. Thisleads to the absorption of SO_(x) in the absorption solutionpredominantly controlling the amount of make-up and bleed of theabsorption loop.

There is a need for a technology that further enhances SO_(x) removalfrom gases produced in industrial processes. There is also a need for atechnology that further enhances CO₂ capture from gases produced inindustrial processes through proper SO_(x) removal from such gases priorto CO₂ capture.

SUMMARY

In some implementations, there is provided a process for desulfurizationof a gas comprising at least water vapour, CO₂ and SO_(x), where x isequal to 2 and/or 3, the gas having an initial gas temperature, theprocess comprising: contacting, in a treatment unit, the gas with acooled alkaline aqueous solution comprising water and a carbonate of analkali metal and having a temperature lower than the initial gastemperature, thereby causing cooling of the gas, condensation of somewater vapour and absorption of the SO_(x) in the carbonate-containingsolution, and producing a SO_(x)-depleted gas and an acidic aqueoussolution comprising sulfate and/or sulfite ions; recovering theSO_(x)-depleted gas from the treatment unit; purging a portion of theacidic aqueous solution exiting the treatment unit (or any other removalstep for removing at least a portion of the sulfate and/or sulfiteions); adding carbonate of the alkali metal to a remaining portion ofthe acidic aqueous solution exiting the treatment unit to obtain analkaline aqueous solution; and cooling the alkaline aqueous solution toresult in the cooled alkaline aqueous solution.

In some implementations, there is provided a system for removing SO_(x)contained in a gas comprising at least water vapour, CO₂ and SO_(x),where x is equal to 2 and/or 3, the gas having an initial gastemperature, the system comprising: a treatment unit for contacting thegas with a cooled alkaline aqueous solution comprising water and acarbonate of an alkali metal and having a temperature lower than theinitial gas temperature, wherein in the treatment unit the gas iscooled, some water vapour is condensed and the SO_(x) are absorbed inthe cooled alkaline aqueous solution; a mixing unit for receiving afirst portion of an acidic aqueous solution comprising sulfate and/orsulfite ions recovered from the treatment unit and adding theretocarbonate of the alkali metal so as to obtain an alkaline aqueoussolution; a purge line for purging a second portion of the acidicaqueous solution recovered from the treatment unit (or any other removalsystem for removing at least a portion of the sulfate and/or sulfiteions); and a cooling unit for cooling the alkaline aqueous solution tobe returned to the treatment unit as the cooled alkaline aqueoussolution.

In some implementations, there is provided a use of an alkalinecarbonate-containing solution for desulfurization and cooling of a gascomprising at least water vapour, CO₂ and SO_(x), where x is equal to 2and/or 3, and recovering a cooled SO_(x)-depleted gas, wherein thealkaline carbonate-containing solution has a temperature lower than aninitial gas temperature and is obtained by mixing an acidic aqueoussolution with a carbonate of an alkali metal, and wherein the acidicaqueous solution comprises sulfate and/or sulfite ions resulting from anabsorption of the SO_(x) of the gas in the alkaline carbonate-containingsolution.

In some implementations, there is provided a process for removing CO₂from a gas comprising at least water vapour, CO₂ and SO_(x), where x isequal to 2 and/or 3, the gas having an initial gas temperature, theprocess comprising a pre-treatment loop for desulfurizing the gas andrecovering a SO_(x)-depleted gas, and an absorption loop for removingCO₂ from the SO_(x)-depleted gas, wherein the process comprises: coolingan alkaline aqueous solution comprising water and a carbonate andbicarbonate of an alkali metal to obtain a cooled alkaline aqueoussolution having a temperature lower than the initial gas temperature;contacting the gas with the cooled alkaline aqueous solution in adesulfurization unit of the pre-treatment loop, thereby causing coolingof the gas, condensation of some water vapour and absorption of theSO_(x) in the cooled alkaline aqueous solution, and producing theSO_(x)-depleted gas and an acidic aqueous solution comprising sulfateand/or sulfite ions; purging a first portion of the acidic aqueoussolution exiting the desulfurization unit; supplying the SO_(x)-depletedgas which contains CO₂ from the desulfurization unit to a CO₂ captureunit of the absorption loop; in the CO₂ capture unit, contacting theSO_(x)-depleted gas with an absorption solution comprising water andcarbonate of the alkali metal, thereby causing absorption of the CO₂ inthe absorption solution and producing a CO₂-depleted gas and a carbonateand bicarbonate-rich absorption solution; treating the carbonate andbicarbonate-rich absorption solution in a stripping unit to generate apurified CO₂ gas and recover a carbonate and bicarbonate-lean absorptionsolution; bleeding a fraction of an absorption solution circulating inthe absorption loop (e.g., from the carbonate and bicarbonate-leanabsorption solution or from the carbonate and bicarbonate-richabsorption solution) as an absorption solution bleed; and mixing theabsorption solution bleed with a second portion of the acidic aqueoussolution exiting the desulfurization unit of the pre-treatment loop toproduce the alkaline aqueous solution.

In some implementations, there is provided a system for removing CO₂from a gas comprising at least water vapour, CO₂ and SO_(x), where x isequal to 2 and/or 3, the gas having an initial gas temperature, thesystem comprising a pre-treatment loop for desulfurizing the gas andrecovering a SO_(x)-depleted gas and an absorption loop for removing CO₂from the SO_(x)-depleted gas, wherein the pre-treatment loop comprises:

a desulfurization unit for contacting the gas with a cooled alkalineaqueous solution comprising water and a carbonate and bicarbonate of analkali metal and having a temperature lower than the initial gastemperature, wherein in the desulfurization unit the gas is cooled, somewater vapour is condensed and the SO_(x) are absorbed in the cooledalkaline aqueous solution;

a mixing unit for mixing a first portion of an acidic aqueous solutioncomprising sulfate and/or sulfite ions recovered from thedesulfurization unit with an absorption solution bleed recovered fromthe absorption loop to obtain an alkaline aqueous solution comprisingwater and the carbonate and bicarbonate of the alkali metal;

a purge line for purging a second portion of the acidic aqueous solutionrecovered from the desulfurization unit; and

a cooling unit for cooling the alkaline aqueous solution to be returnedto the desulfurization unit as the cooled alkaline aqueous solution; and

wherein the absorption loop comprises:

a CO₂ capture unit for contacting the SO_(x)-depleted gas with anabsorption solution comprising water and carbonate of the alkali metaland producing a CO₂-depleted gas and a carbonate and bicarbonate-richabsorption solution; and

a stripping unit for treating the carbonate and bicarbonate-richabsorption solution to recover a purified CO₂ gas and generate acarbonate and bicarbonate-lean absorption solution at least a part ofwhich is recirculated back into the CO₂ capture unit at the absorptionsolution.

In some implementations, there is provided a process for desulfurizationof a gas comprising at least water vapour, CO₂ and SO_(x), where x isequal to 2 and/or 3, the process comprising: contacting, in a treatmentunit, the gas with an alkaline aqueous solution comprising water and acarbonate of an alkali metal to cause absorption of the SO_(x) in thealkaline aqueous solution, to produce an SO_(x)-depleted gas and anacidic aqueous solution comprising sulfate and/or sulfite ions;recovering the SO_(x)-depleted gas from the treatment unit; withdrawingthe acidic aqueous solution from the treatment unit; purging a portionof the acidic aqueous solution as a purged stream and producing aremaining portion of the acidic aqueous solution; adding carbonate of analkali metal to the remaining portion of the acidic aqueous solution toobtain a made-up alkaline aqueous solution; and reintroducing themade-up alkaline aqueous solution into the treatment unit.

In some implementations, there is provided a system for removing SO_(x)contained in a gas comprising at least water vapour, CO₂ and SO_(x),where x is equal to 2 and/or 3, the system comprising: a treatment unitfor contacting the gas with an alkaline aqueous solution comprisingwater and a carbonate of an alkali metal, wherein in the treatment unitsome water vapour is condensed and the SO_(x) are absorbed in thealkaline aqueous solution to form an acidic aqueous solution comprisingsulfate and/or sulfite ions; a mixing unit for receiving a first portionof the acidic aqueous solution recovered from the treatment unit and foradding thereto carbonate of the alkali metal so as to obtain aregenerated alkaline aqueous solution; a purge line for purging a secondportion of the acidic aqueous solution recovered from the treatmentunit; and a recirculation line for feeding the regenerated alkalineaqueous solution back into the treatment unit.

In some implementations, there is provided a use of an alkalinecarbonate-containing solution for desulfurization of a gas comprising atleast water vapour, CO₂ and SO_(x), where x is equal to 2 and/or 3, andrecovering a cooled SO_(x)-depleted gas, wherein the alkalinecarbonate-containing solution is obtained by mixing an acidic aqueoussolution with a carbonate of an alkali metal, and wherein the acidicaqueous solution comprises sulfate and/or sulfite ions resulting from anabsorption of the SO_(x) of the gas in the alkaline carbonate-containingsolution.

In some implementations, there is provided a process for removing CO₂from a gas comprising at least water vapour, CO₂ and SO_(x), where x isequal to 2 and/or 3, the process comprising a pre-treatment loop fordesulfurizing the gas and recovering a SO_(x)-depleted gas, and anabsorption loop for removing CO₂ from the SO_(x)-depleted gas, whereinthe process comprises: contacting the SO_(x)-depleted gas with anabsorption solution comprising water and carbonate of the alkali metal,thereby causing absorption of the CO₂ in the absorption solution andproducing a CO₂-depleted gas and a carbonate and bicarbonate-richabsorption solution; treating the carbonate and bicarbonate-richabsorption solution in a stripping unit to generate a purified CO₂ gasand recover a carbonate and bicarbonate-lean absorption solution;bleeding a fraction of the absorption solution circulating in theabsorption loop as an absorption solution bleed; supplying at least aportion of the absorption solution bleed to the pre-treatment loop aspart of a desulfurization solution; contacting the gas with thedesulfurization solution in a desulfurization unit of the pre-treatmentloop, thereby causing absorption of the SO_(x) in the alkaline aqueoussolution, and producing the SO_(x)-depleted gas and an acidic aqueoussolution comprising sulfate and/or sulfite ions; purging a first portionof the acidic aqueous solution exiting the desulfurization unit;supplying the SO_(x)-depleted gas which contains CO₂ from thedesulfurization unit to a CO₂ capture unit of the absorption loop;mixing the second portion of the acidic aqueous solution exiting thedesulfurization unit of the pre-treatment loop with at least a portionof the absorption solution bleed, to produce the desulfurizationsolution.

In some implementations, there is provided a system for removing CO₂from a gas comprising at least water vapour, CO₂ and SO_(x), where x isequal to 2 and/or 3, the system comprising a pre-treatment loop fordesulfurizing the gas and recovering a SO_(x)-depleted gas and anabsorption loop for removing CO₂ from the SO_(x)-depleted gas, whereinthe pre-treatment loop comprises:

a desulfurization unit for contacting the gas with an alkaline aqueoussolution comprising water and a carbonate and bicarbonate of an alkalimetal, wherein in the desulfurization unit SO_(x) are absorbed in thealkaline aqueous solution to produce an acidic aqueous solution;

a mixing unit for mixing a first portion of the acidic aqueous solutioncomprising sulfate and/or sulfite ions recovered from thedesulfurization unit with an absorption solution bleed recovered fromthe absorption loop to obtain an alkaline aqueous solution comprisingwater and the carbonate and bicarbonate of the alkali metal; and

a purge line for purging a second portion of the acidic aqueous solutionrecovered from the desulfurization unit; and

wherein the absorption loop comprises:

a CO₂ capture unit for contacting the SO_(x)-depleted gas with anabsorption solution comprising water and carbonate of the alkali metaland producing a CO₂-depleted gas and a carbonate and bicarbonate-richabsorption solution; and

a stripping unit for treating the carbonate and bicarbonate-richabsorption solution to recover a purified CO₂ gas and generate acarbonate and bicarbonate-lean absorption solution at least a part ofwhich is recirculated back into the CO₂ capture unit at the absorptionsolution.

In some implementations, there is provided a use of a bleed streamobtained from a CO₂-capture process and comprising sodium or potassiumcarbonate for desulfurization of a gas comprising water vapour, CO₂ andSO_(x), where x is equal to 2 and/or 3 and production of anSO_(x)-depleted gas.

In some implementations, there is provided an SO_(x) absorbent solutioncomprising: a bleed stream obtained from a CO₂-capture process andcomprising sodium or potassium carbonate; and an acidic aqueous solutionobtained from desulfurization of a SO_(x)-containing gas. In someimplementations, there is provided a gas pre-treatment solution forabsorbing contaminants from a CO₂-containing gas, comprising: a bleedstream obtained from a CO₂-capture process and comprising sodium orpotassium carbonate; and an acidic aqueous solution obtained fromdesulfurization of a SO_(x)-containing gas. The SO_(x) absorbentsolution and/or the gas pre-treatment solution can have one or morefeature as described herein.

In some implementations, there is provided a process for desulfurizationof a gas comprising at least water vapour, CO₂ and SO_(x), where x isequal to 2 and/or 3, the process comprising: contacting, in a treatmentunit, the gas with an alkaline aqueous solution comprising water and acarbonate of an alkali metal to cause absorption of the SO_(x) in thealkaline aqueous solution, to produce an SO_(x)-depleted gas and anacidic aqueous solution comprising sulfate and/or sulfite ions;withdrawing the SO_(x)-depleted gas from the treatment unit; withdrawingthe acidic aqueous solution from the treatment unit; removing at least aportion of the sulfate and/or sulfite ions from the acidic aqueoussolution to produce a remaining acidic aqueous solution; addingcarbonate of an alkali metal to the remaining acidic aqueous solution toobtain a made-up alkaline aqueous solution; and reintroducing themade-up alkaline aqueous solution into the treatment unit.

In some implementations, the removing of at least a portion of thesulfate and/or sulfite ions from the acidic aqueous solution cancomprise purging a portion thereof to produce a remaining portionthereof as the remaining acidic aqueous solution. In addition, it isnoted that where such purging or use of a purge line is mentioned hereinit could be feasible alternatively or additionally perform other methodsto deplete the acidic aqueous solution of sulfate and/or sulfite ions.

It should be noted that any of the features described above and/orherein can be combined with any other features, processes and/or systemsdescribed herein, unless such features would be clearly incompatible.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 (prior art) is a process diagram representing a conventional CO₂capture process configuration where the flue gas is cooled down using aquench unit and then sent to the CO₂ capture unit. The absorptionsolution is bled to maintain adequate performance of the unit and freshabsorption solution is added to compensate for the bleed stream.

FIG. 2 is a process diagram representing a process for SO_(x) capturefrom a flue gas according to an embodiment.

FIG. 3 is a process diagram representing a process for treating a fluegas showing the integration of a pre-treatment loop wherein the gas iscooled and desulfurized, with a CO₂ capture loop for removing CO₂ fromthe desulfurized gas, according to an embodiment.

FIG. 4 is a process flow diagram of a process for removing CO₂ from aflue gas based on the use of a potassium carbonate solution as theabsorption solution.

FIG. 5 is a process flow diagram representing the SO_(x) removalpre-treatment loop used for process simulations, according to anembodiment.

FIG. 6 is a process flow diagram representing a process for treating aflue gas showing the integration of the SO_(x) removal pre-treatmentloop with the CO₂ capture loop, according to an embodiment.

FIG. 7 is a graph representing the impact of column height andpre-treatment loop flow rate on the SO_(x) capture. Process conditionsare: absorption solution bleed flow rate of 0.092 m³h⁻¹, column floodingmaintained at 70%, absorption solution bleed at 17 wt % K₂CO₃,temperature of the pre-treatment loop flow at 30° C.

FIG. 8 is a graph representing the effect of the pre-treatment loop flowtemperature on SO_(x) capture and absorption solution bleed flow rate.Process conditions are: column height of 5 m; column flooding maintainedat 70%; constant absorption solution bleed flow rate of 0.092 m³h⁻¹;pre-treatment loop flow rate of 200 m³h⁻¹; inlet gas SO₂ concentrationof 10 ppmv; absorption solution bleed at 17 wt % K₂CO₃.

DETAILED DESCRIPTION

In a first aspect, the present process and system relates to thetreatment of a gas comprising at least water vapour, CO₂ and SO_(x),such as a flue gas, e.g. a post-combustion flue gas, to remove theSO_(x) from the gas while cooling the gas in a single treatment unit. Ina second aspect, the process and system relate to a treatment forremoving CO₂ from a gas comprising at least water vapour, CO₂ andSO_(x), involving a pre-treatment for removing SO_(x) from the gas,before the CO₂ capture.

In the present description, the treatment unit for SO_(x) removal mayinterchangeably be referred to as desulfurization unit, quench unit orquench tower. In one embodiment, the quench tower may consist in acontactor such as a packed column with random packing, a packed columnwith structured packing, a venturi, a barometric leg, an eductor, aspraying device, a demister pad, etc.

According to the present process and system, SO_(x) represents thespecies SO₂ and SO₃. Water vapour represents water in gaseous form. Thegas to be treated may further comprise nitrogen (N₂), oxygen (O₂), NO,NO₂, and/or H₂S, depending on the process from which the gas originates.In one embodiment, the gas may present a concentration in SO_(x) of fromabout 10 to about 100 ppmv. In some cases, the gas may further compriseNO_(x). (x′=1 and/or 2). In one embodiment, the concentration in NO_(x)in the gas may be of from about 10 to about 150 ppmv. In anotherembodiment, the gas may also comprise N₂, O₂ and/or other speciesincluding for example solid particles.

The term “about”, as used herein before any numerical value, meanswithin an acceptable error range for the particular value as determinedby one of ordinary skill in the art. This error range may depend in parton how the value is measured or determined, i.e. the limitations of themeasurement system. It is commonly accepted that a 10% precision measureis acceptable and encompasses the term “about”.

A process and system for SO_(x) capture from a combustion or flue gasaccording to the first aspect will now be described referring to FIG. 2.The combustion or flue gas (1) comprising at least H₂O (in gaseousform), CO₂ and SO_(x) (x=2 and/or 3) is fed to a quench tower (2′) inwhich it is contacted with an aqueous solution comprising a carbonate ofan alkali metal (22).

In some embodiments, the aqueous solution comprising the alkali metalcarbonate (22) may comprise sodium carbonate (Na₂CO₃) or potassiumcarbonate (K₂CO₃). In some embodiments, the alkali metal carbonatecomprises K₂CO₃. The aqueous solution of the alkali metal carbonate (22)may further comprises the corresponding bicarbonate of the alkali metal.Hence, if stream (22) comprises K₂CO₃ as the alkali metal carbonate, itmay also comprise potassium bicarbonate KHCO₃. The aqueous solution ofthe alkali metal carbonate (22) optionally comprising the correspondingalkali metal bicarbonate species, may be interchangeably referred to asan alkaline aqueous solution or an alkaline carbonate-containingsolution. In one embodiment, the pH of the alkaline aqueous solution maybe above 7 and up to about 9.5, or it may be above 7 and up to about 9.In another embodiment, the concentration in alkali metal carbonate inalkaline aqueous solution (22) may be from about 1 mM to about 1 M (theunit “M” corresponding to mol L⁻¹). In some embodiments, theconcentration in alkali metal carbonate in alkaline aqueous solution(22) can be from about 1 mM to about 700 mM, 5 mM to about 500 mM, or 50mM to about 250 mM.

The alkaline aqueous solution (22) sent to the quench tower for beingcontacted with the gas, generally has a temperature below thetemperature of the gas. A cooling unit (18) may thus be providedupstream the quench tower (2′) to cool the alkaline aqueous solution(22). Cooling unit (18) may comprise a heat exchanger in which cooledwater is used as cooling fluid (streams 20, 21). In one embodiment, thetemperature of the cooled alkaline aqueous solution may be from about 5°C. to about 60° C. In another embodiment, the cooled temperaturealkaline aqueous solution can be from about 5° C. to about 50° C. In afurther embodiment, the temperature of the cooled alkaline aqueoussolution may be from about 10° C. to about 50° C. In another embodiment,the cooled alkaline aqueous solution may have a temperature that is fromabout 0° C. to about 200° C., from about 20° C. to about 150° C., orfrom about 50° C. to about 100° C., below the temperature of the gas.

The cooled alkaline aqueous solution (22) exiting the cooling unit isthen fed to the quench tower (2′). In the quench tower (2′), the contactbetween the flue gas and the alkaline aqueous solution (22) results in alowering of the gas temperature, removal of some water from the gasthrough water vapour condensation in the solution, as well as removal ofthe SO_(x) from the gas by absorption in the alkaline aqueous solution.The contact between the flue gas and the solution (22) results in aclean, cooled SO_(x)-depleted gas (5) which may be sent to furthertreatment as required. For example, the cooled SO_(x)-depleted gas (5)may be sent to a CO₂ capture process to further remove CO₂ therefrom, aswill be explained below in connection with the second aspect.

The solution (17) leaving the quench tower (2′) thus contains absorbedSO_(x) in the form of sulfate (SO₄ ²⁻) and/or sulfite (SO₃ ²⁻) ions andto some extent condensed water vapour. The pH of solution (17) is thusacidic, below 7. Solution (17) may thus be referred to as an acidicaqueous solution. Sulfate ions may be susceptible to precipitation inpotassium carbonate absorption solution (where the alkali metal is K).However, because the water vapour condenses in the solution, thedilution effect may make precipitation unlikely. Solution (17) may alsocontain absorbed particles and/or ashes transported by the gas in thequench tower. It may be desirable to remove such particles and/or ashes.This may be done for example at the exit of the quench tower using aseparator device (not shown in FIG. 2). In one embodiment, theseparation device may comprise a radial vane separator, a Schoepentoeterdevice, a cyclone, venturi, a settling system, a filtration unit, etc.Additional treatment of the solution (17) can also be performed prior torecycling back into the quench tower (2′) to modify its composition orother properties.

Still referring to FIG. 2, the acidic aqueous solution (17) is then sentto a mixing unit (19) wherein it is mixed with some alkali metalcarbonate and optionally the corresponding bicarbonate (15). The alkalimetal carbonate may be added to the acidic aqueous solution (17) in asolid form or in solution in water. In one embodiment, the alkali metalcarbonate is added to the acidic aqueous solution, in solution in water.In another embodiment, the solution in water of the alkali metal (15)may be derived from a CO₂-capture process, for example it may be anabsorption solution bleed derived from a CO₂-capture process, as will befurther detailed below in connection with the second aspect. Upon mixingthe acidic solution (17) with the alkali metal carbonate, the pH of thesolution is increased above 7, resulting in the alkaline aqueoussolution (22), which is then returned to the cooler (18) and then thequench tower (2′) for further gas desulfurization. Regarding the mixer(19), it should be noted that it can have various constructions andconfigurations, such as a Tee pipe joint, a stirred tank mixer, orvarious other types of mixers, depending on the form of the make-upalkali metal carbonate being added as well as other process factors.

The desulfurization system also includes a purge line (16) that isprovided for purging a portion of the acidic aqueous solution (17)exiting the quench tower (2′), so as to maintain a mass balance of thedesulfurization process. In one embodiment, purging may be performed ata flowrate determined by a water vapour condensation rate and analkaline aqueous solution flowrate. A level sensor (not shown) mayfurther be provided upstream of the purge line to detect the level ofliquid in the system and allow controlling the purge line flow. Thepurging of a portion of the acidic aqueous solution may be performedcontinuously or periodically.

A process and system for CO₂ capture from a combustion or flue gasinvolving a pre-treatment for removing SO_(x) from the gas, according tothe second aspect will now be described referring to FIG. 3.

In FIG. 3, the pre-treatment loop (A) wherein the gas is cooled anddesulfurized, substantially corresponds to the desulfurizationprocess/system previously described with respect to the first aspect.Hence, the features of the various streams and units previouslydescribed in reference to FIG. 2 may also be considered in relation withpre-treatment loop (A) of FIG. 3. This includes, for instance, thefeatures of the components in the streams, their temperatures,concentrations, pH etc., as well as the features of the quench unit,mixing unit, separation device, cooling unit, level sensor etc.

The pre-treatment loop (A) thus comprises sending gas (1) comprisingwater vapour, CO₂ and SO_(x), and optionally other species such asNO_(x), to the quench unit (2′). In the quench unit (2′) the gas iscooled to a temperature suitable for the subsequent CO₂ capture unit,some water vapour is condensed as a liquid stream, and a fraction of theSO_(x) present in the gas is removed. Cooling of the gas and SO_(x)removal may be obtained through contacting the gas with alkaline aqueoussolution (22), which has been cooled in cooling unit (18) prior to itsentrance in the quench unit (2′). As a result of contacting the fluegas, the alkaline aqueous solution is warmed, and its water content isincreased due to the water vapour condensation. In addition, its pH isdecreased due to the absorption of the SO_(x) in the solution. Theacidic aqueous stream (17) leaving the quench unit is sent to mixingunit (19) where it is mixed with absorption solution bleed stream (15)of the absorption loop (B), also referred to as CO₂ capture loop. Theabsorption solution bleed stream (15) comprises alkali metal carbonateand bicarbonate in solution. Hence, upon mixing the acidic aqueousstream (17) with the bleed stream (15), the pH of the resulting solutionincreases, resulting in an alkaline aqueous solution, which is returnedas stream (22) towards cooler (18). The SO_(x)-depleted gas (5) leavingthe quench unit with a lower temperature and a lower SO_(x)concentration is sent to the absorption loop (B). The mass balance ofthe pre-treatment loop (A) may be obtained using the purge line (16). Inone embodiment, purging may be performed at a flowrate determined by awater vapour condensation rate and a flowrate of absorption solutionbleed (15). It should be noted that the SO_(x)-depleted gas (5) couldalso be subjected to additional pre-treatments prior to entering theabsorption loop (B), if desired.

The absorption solution bleed stream (15) can be taken from variouspoints in the absorption loop (B). In FIGS. 3 and 6 the absorptionsolution bleed stream (15) is taken off of the regenerated solutionexiting the bottom of the stripping unit. However, the absorptionsolution bleed stream could be taken from other streams of theabsorption loop (B), such as the absorption solution (10) exiting theheat exchanger (9) and which is thus cooler than the regeneratedsolution exiting the bottom of the stripping unit. The absorptionsolution bleed stream could be taken from a CO₂-loaded stream, such asthe loaded stream (8) exiting the absorption unit or the loaded streamexiting the heat exchanger prior to entering the stripping unit (11).Thus, the absorption solution bleed stream can be taken from the loadedor lean streams in the absorption loop, or could be a combination ofsuch streams.

The absorption loop (B) as shown in FIG. 3, may comprise an absorptionunit (6) in which the SO_(x)-depleted gas (5), which contains CO₂, maybe treated for removing CO₂ therefrom. Conventional absorbers known inthe field may be used as the absorption unit (6). For instance, the CO₂absorption unit may be a bubble column, a spray scrubber, a packedcolumn with structured packing or a packed column with random packing, arotating packed bed, or others. In the absorption unit (6), CO₂ isabsorbed in an absorption solution comprising water and a carbonate ofan alkali metal resulting in the production of a CO₂-depleted gas (7)and a carbonate and bicarbonate-rich absorption solution (8) or simply“rich absorption solution” (8). The flue gas with a lower CO₂ content(7) is discharged at the top of the absorption unit to the atmosphere orit is sent to another downstream process.

In one embodiment, the alkali metal may be sodium or potassium. If thealkali metal is potassium, the absorption solution would thus comprisepotassium carbonate and water. In one embodiment, the absorptionsolution used in the CO₂ capture unit may have a concentration of fromabout 1 M to about 5 M. It is also noted that the potassium carbonateabsorption solution could include additional chemical compounds and/orcatalysts. The additional chemical compounds and/or catalysts caninclude promoters that accelerate CO₂ absorption and/or provide otherbenefits to absorption or desorption performance. Examples of additionalchemical compounds that can be present in the absorption solution areamino acids or salts or derivatives thereof, amines, inorganicadditives, and/or other absorbent promoters.

In another embodiment, the CO₂ capture in the absorption unit (6) may beperformed in the presence of an enzyme catalyzing the CO₂ hydration suchas a carbonic anhydrase (CA) or an analogue thereof. Hence, in theabsorption unit (6), CO₂ may dissolve in the absorption solution, whichmay contain the CA, and then reacts with the hydroxide ions (Equation 8)and water (Equations 9 and 10). The CA-catalyzed CO₂ hydration reaction(Equation 10) is the dominant reaction in the process.

$\begin{matrix}\left. {{CO}_{2} + {OH}^{-}}\rightarrow{HCO}_{3}^{-} \right. & {{Equation}\mspace{14mu} 8} \\\left. {{CO}_{2} + {H_{2}O}}\rightarrow\left. {H_{2}{CO}_{3}}\rightarrow{{HCO}_{3}^{-} + H^{+}} \right. \right. & {{Equation}\mspace{14mu} 9} \\{{CO}_{2} + {H_{2}O\mspace{14mu}\mspace{14mu}{HCO}_{3}^{-}} + {H^{+}.}} & {{Equation}\mspace{14mu} 10}\end{matrix}$

The carbonic anhydrase which may be used to enhance CO₂ capture, may befrom human, bacterial, fungal or other organism origins, havingthermostable or other stability properties, as long as the carbonicanhydrase or analogue thereof can catalyze the hydration of the carbondioxide to form hydrogen and bicarbonate. It should also be noted that“carbonic anhydrase or an analogue thereof” as used herein includesnaturally occurring, modified, recombinant and/or synthetic enzymesincluding chemically modified enzymes, enzyme aggregates, cross-linkedenzymes, enzyme particles, enzyme-polymer complexes, polypeptidefragments, enzyme-like chemicals such as small molecules mimicking theactive site of carbonic anhydrase enzymes and any other functionalanalogue of the enzyme carbonic anhydrase.

The enzyme carbonic anhydrase may have a molecular weight up to about100,000 daltons. In another embodiment, the carbonic anhydrase can be ofrelatively low molecular weight (e.g. 30,000 daltons).

The carbonic anhydrase or analogue thereof may be provided in variousways. It may be supported on or in particles that flow with thesolution, directly bonded to the surface of particles, entrapped insideor fixed to a porous support material matrix, entrapped inside or fixedto a porous coating material that is provided around a support particlethat is itself porous or non-porous, or present as crosslinked enzymeaggregates (CLEA) or crosslinked enzyme crystals (CLEC). The enzymes maybe provided immobilized within the reactor itself (e.g., on packing), ormay be free in the solution. When the CA is used in association withparticles that flow in solution, the enzymatic particles can be preparedby various immobilization techniques and then deployed in the system.When the CA is used in non-immobilized form, it can be added in powderform, enzyme-solution form, or enzyme dispersion form, into theabsorption solution where it can become a soluble part of the absorptionsolution.

In one embodiment, the CA enzyme concentration may be below 0.1% byweight of the absorption solution. In other examples, the CA enzymeconcentration can be above this value, depending on various factors suchas process design, enzyme activity and enzyme stability.

Still referring to FIG. 3, the carbonate and bicarbonate-rich absorptionsolution (8) may be fed to a stripping unit (11). Stripping unit (11),which can also be called a desorption unit or a regeneration unit, mayserve for the regeneration of the absorption solution and the recoveryof the CO₂ as a gas (12). In one embodiment, the carbonate andbicarbonate-rich absorption solution (8) may be heated by passingthrough a heat exchanger (9) before being sent to the stripper (11). Inthe stripping unit (11), the rich absorption solution (8) may flowdownwards by gravity while contacting a stripping gas which may consistof water vapour at a temperature ranging, for instance, between 60° C.and 85° C. The stripping unit may be operated under a partial vacuum toallow for this low temperature range. A vacuum pump may be used for thispurpose. The composition of the stripping gas may be such that thedissolved CO₂ may be released from the liquid phase and consequentlybicarbonate ions transformed back into dissolved CO₂ (Equation 11) andthen into gaseous CO₂, which may be released as stream (12). Thestripping gas is preferably obtained by passing a portion of thesolution through a reboiler and generating the stripping gas (see FIG.6, for example), although other methods of providing a stripping gas canalso be used.CO₂+H₂O→H₂CO₃→HCO₃ ⁻+H⁺  Equation 11.

CA may also be present in the stripping unit and may catalyze thetransformation of the bicarbonate ions into dissolved CO₂ (Equation 10).The absorption solution, now made lean in CO₂, leaving the strippingunit and referred to as a carbonate and bicarbonate-lean absorptionsolution (10) or simply “lean absorption solution” (10) may be pumpedand cooled down by passing through the heat exchanger (9) and fed backinto the top of the absorption unit (6). A fraction of the carbonate andbicarbonate-lean absorption solution (10) is sent to pre-treatment loop(A) as an absorption bleed stream (15).

Under the complete absorption/stripping cycle, the CA enzyme may beexposed to a pH ranging between about 9 and about 10. The gas (12)leaving the stripping unit, comprising water vapour and gaseous CO₂, maybe sent to a condenser. Once condensed, the water may then be sent backto the stripping unit and the CO₂ may be recovered for future use. Tomaintain the water mass balance, water may be added to the absorptionloop (B) through stream (40). When additives (e.g., catalysts such asenzymes, promoters, etc.) are used in the absorption solution, make-upof such additives can be provided via a make-up line at various pointsin the process.

As previously explained, when the gas to be treated contains NO_(x)species, the NO_(x) can be absorbed by the absorption solution andtransformed in nitrite/nitrate ions in solutions as shown in Equations5, 6 and 7. Over time, the absorption solution in the absorption loop(B) may become richer in nitrite and nitrate ions. The absorptionsolution bleed (15) flow rate may be adjusted to maintain concentrationlevels adequate to maintain a continuous optimal CO₂ captureperformance.

The present CO₂ capture process and system may present variousadvantages. First, no separate desulfurization unit may be required forSO_(x) removal prior to CO₂ capture. Indeed, both desulfurization andcooling of the gas can be performed in the same process unit instead ofseveral process units. This allows reducing costs and is economicallybeneficial. Secondly, the present process/system recycles a waste stream(i.e., the absorption solution bleed stream) to pre-treat the gas andselectively remove contaminants, such as SO_(x). Further, the use ofcarbonate absorption solution in the main absorption loop can be reducedthanks to the present process/system. These features may reduce theenvironmental impact of the process and the operating costs associatedwith the consumption of the absorption solution. Also, removal of SO_(x)from the gas stream in the pre-treatment loop generates sulfates, adesirable by-product which may be used in fertilisers.

The present process and system may also limit the impact of SO_(x) andNO_(x) (if the gas contains such species) on the CO₂ captureperformance. Thanks to the pre-treatment step to remove the SO_(x), itmay be possible to minimize the sulfate ion concentration in theabsorption solution. The nitrate and/or nitrite levels of the absorptionloop may further be controlled and reduced. The present process/systemalso takes advantage of the different absorbing rates of the sulfidationand nitrification reactions in the carbonate absorption solution. Moreparticularly, since the absorption solution bleed at its nitrificationthreshold point, still has a high absorption capacity, it can be used toselectively absorb sulfates from the gas stream impurities. Morespecifically, the absorption solution bleed can be mixed or combinedwith the solution used to cool the flue gas in the quench unit,resulting in a high SO_(x) removal efficiency, which translates into amuch lower concentration of sulfate ions in the absorption solution ofthe CO₂ capture unit, which in turn positively impacts bleed flow rates,enzyme and absorption solution make-up rates by considerably decreasingthem. The driving force behind the SO_(x) capture is the pH of thetreatment solution in the pre-treatment loop. During standard operation,the aqueous solution is acidic because of the reaction with CO₂, SO_(x)and NO_(x). However, by adding the absorption solution bleed, which hasa pH over 9, the pre-treatment loop solution becomes alkaline and mayfurther absorb SO_(x) and NO_(x). This results in a better processperformance because the waste disposal and correspondingly the input offresh solution may be considerably decreased. This reduces theenvironmental impact of the process and the operation costs associatedwith the consumption of the absorption solution.

All the documents mentioned in the present description are incorporatedherein by reference.

EXAMPLES AND EXPERIMENTATION

The following examples illustrate different aspects of the process andsystem described herein. For this purpose, Protreat® simulator was usedto perform mass and energy balances as well as design of the packed bedcolumns. Protreat® is a state-of-the-art rate-based simulator for gastreating marketed by Optimized Gas Treating Inc. (OGT) of Houston, Tex.This simulator was implemented with a kinetic module to represent thecatalytic effect of carbonic anhydrase's enzyme in a K₂CO₃/KHCO₃absorption solution on CO₂ capture.

Example 1 (Comparative Example): Description of 100 Tonnes Per Day (Tpd)CO₂ Capture Unit Using an Enzyme Based Solution without SO_(x) Removal

A CO₂ capture process is used to remove 90% of CO₂ present in a fluegas. The flue gas composition is given in Table 1. To take into accountthe fact that SO_(x) and NO_(x) concentration can vary depending on theflue gas source, their concentrations were changed according to theindicated concentration range in the Table 1. In the present example,SO_(x) consisted of SO₂ only, and SO_(x) removal was consideredequivalent to SO₂ removal.

TABLE 1 Inlet Gas Parameters Parameter 100 tpd Case Flow (kg/h) 46-300Temperature (° C.) 70  Pressure (kPa) 102   H₂O (mol %) 18.0  CO₂ (mol%) 8.2 SO₂ (ppmv*) 10-100 N₂ (mol %) 70.5  O₂ (mol %) 2.5 Ar (mol %) 0.5NO_(x) (ppmv) 10-150 (*1 ppmv = 1 μL/L)The CO₂ capture process considered for the process simulations is shownin FIG. 4 and is further described below.

The flue gas (1), having a composition shown in Table 1, is directed toa cooling unit (2) having a packed column configuration, using a blower(23). The flue gas is cooled with water at a desirable temperature forthe process which is 30° C. for the present example. The water streamleaving the cooling tower is then sent to a cooling system (not shown)and then sent back to the cooling unit (2). The cooled flue gas, at atemperature of 30° C., is then sent to the packed column absorber unit(6). The flue gas enters at the bottom of the packed column and flowsupwards and contacts an aqueous absorption solution (25), goingdownwards by gravity. The absorption solution (25) comprises potassiumcarbonate, potassium bicarbonate and the enzyme carbonic anhydrase (CA).The potassium concentration in the solution is 2.9 M. The concentrationsin carbonate and bicarbonate ions depend on the absorption and strippingprocess conditions. The CA enzyme concentration is below 0.1% by weightof the absorption solution. CO₂ dissolves in the solution and thenreacts with the hydroxide ions (equation 8) and water (equations 9 and10).

The CA-catalyzed CO₂ hydration reaction (equation 10) is the dominantreaction in the process. The fast enzymatic reaction enables a maximumconcentration gradient across the gas/liquid interface and results in amaximum CO₂ transfer rate from the gas phase to the liquid phase, and,consequently in a high CO₂ capture performance. The flue gas with alower CO₂ content (7) is discharged at the top of the absorber to theatmosphere or it is sent to another downstream process.

Afterwards, the absorption solution containing CO₂ in the form ofbicarbonate ions (8), also referred to as the rich absorption solution,is pumped and heated by passing through a heat exchanger (37) and thenfed at the top of the stripper (11) as stream (24). The solution flowsdownwards by gravity while contacting a stripping gas (39) consisting ofwater vapour at a temperature ranging between 60 and 85° C. The stripperis operated under a partial vacuum to allow for this low temperaturerange to work, a vacuum pump (35) is used for this purpose. Thecomposition of the stripping gas is such that the dissolved CO₂ isreleased from the liquid phase and consequently bicarbonate ions aretransformed back into dissolved CO₂ (equation 11) and then into gaseousCO₂.

CA is also present in the stripper and catalyzes the transformation ofthe bicarbonate ions into dissolved CO₂ (equation 10). The absorptionsolution, now made lean in CO₂, leaves the stripper at its bottom (26).A fraction of the absorption solution is pumped as solution (30) towardsthe reboiler (27) where water is evaporated and then sent back to thestripper as the stripping gas (39). The energy for water evaporation isprovided using waste heat coming from the plant where the capture unitis implemented. Waste heat may for example be supplied using hot water(28) (e.g. at a temperature above 80° C.). The absorption solution (25)is then pumped and cooled down by passing through the heat exchanger(37) and the cooler (38) and is fed back into the top of the absorberunit (6). Under the complete absorption/stripping cycle, the enzyme isexposed to a pH ranging between 9 and 10. The gas leaving the stripper(31), consisting of water vapour and gaseous CO₂, is sent to a condenser(32). Once condensed, the water (33) is then sent back to the stripperand the CO₂ is sent from the vacuum pump (35) to the mechanicalcompression unit (36) for future use. To maintain the water massbalance, water is added to the process through stream (40).

As the SO₄ ²⁻ concentration level approaches the maximum concentrationlevel, and to avoid any K₂SO₄ precipitation, a fraction of theabsorption solution is bled and sent toward the cooling tower (2) asdescribed above. This sulfate concentration level leading to theprecipitation is dependent on the composition of the absorption solutionand more specifically to the potassium ion concentration in thesolution.

Process simulations were conducted to determine the composition of theabsorption solution bleed stream required to maintain the SO₄ ⁻² ionconcentration level at a maximum concentration of 0.125 M and avoidK₂SO₄ precipitation in a K₂CO₃ absorption solution. The reasons for thiswere explained above. It was experimentally determined that under theprocess conditions K₂SO₄ precipitation is present when the sulfate ionconcentration is close to 0.15 M.

For a flue gas of Table 1 containing 10 ppmv SO₂ and 10 ppmv NO_(x), theabsorption solution bleed composition (stream (13)) were determined fortwo absorption solutions compositions: 17 and 45 wt % K₂CO₃. Results areprovided in Table 2. For both cases, the bleed flow rate is 0.092 m³/hand the bleed flow temperature is 65° C. SO₂ removal in the cooling unitis less than 1% under these conditions.

TABLE 2 Absorption Solution Bleed Composition K₂CO₃ concentrationParameter 17 wt. % 45 wt. % K₂CO₃ (M)  0.87  2.88 KHCO₃ (M)  1.16  3.84Enzyme (gL⁻¹) 0.5 0.5 SO₄ ²⁻ (M)  0.125  0.125

Example 2: Description of 100 Tonnes Per Day CO₂ Capture Unit Using anEnzyme Based Solution Comprising a SO_(x) Removal in a Pre-TreatmentLoop

In the present example, it is considered that a pre-treatment loop isadded to the CO₂ capture unit described in Example 1 in theconfiguration previously shown in FIG. 3. A simple simulation wasdesigned to emulate a pre-treatment loop for absorption solution bleedvaluation (see FIG. 5). The complete process is as shown in FIG. 6. Forthe demonstration purpose, the treatment unit or «quench tower» is apacked column. The quench tower is operated at atmospheric pressure. Theliquid is circulated using a centrifugal pump. The liquid flowrate inthe purge line is equivalent to the flue gas water vapour condensationrate and the absorption solution bleed flow rate.

As a first simulation, the flue gas of Table 1 was considered, where theNO_(x) and SO₂ concentrations were set at 10 ppmv. This enables a directevaluation of the impact of the pre-treatment loop on the absorptionsolution bleed flow rate by comparing with the value obtained in Example1 which is 0.092 m³/h. As a base case, the simulation was runconsidering a 5 m quench tower and a pre-treatment loop flow rate of 200m³/h. The quench tower is operated at 70% flooding and at a temperatureof 30° C. so that the flue gas entering the absorber of the absorptionloop is at a temperature of 30° C. CO₂ capture process conditions wereas described in Example 1 (except for what concerns the use of the bleedstream for SO_(x) removal) where the absorption solution is 17% wtK₂CO₃. The simulations were first started by considering the bleed flowrate determined in Example 1 and were then conducted iteratively untilthe bleed flow rate converged.

The simulations indicated that by using the absorption solution bleedstream for SO₂ removal, the bleed stream flow rate was decreased from0.092 down to 0.012 m³/h. This represents an 8-fold decrease of thebleed flow rate relative to the case without SO_(x) treatment when theabsorption solution is 17% wt K₂CO₃. As demonstrated in Table 3, thesolution entering the cooling unit (2) in Example 1 according to aconventional process, has an acidic pH of 4.42 which does not permit SO₂capture (less than 1%). However, by adding the absorption solution bledfrom the absorption loop to the acidic aqueous solution exiting thequench tower (2′), the flow becomes an alkaline solution with pH of 7.78which promotes SO_(x) capture. In this case, SO₂ removal is 85%.

TABLE 3 Solution inlet to cooling/quench unit when the CO₂ absorptionsolution is 17 wt % K₂CO₃ and the flue gas contains 10 ppmv NO_(x) and10 ppm SO₂ Solution composition (mol fraction) Cooling only SO₂ removalWater 1.00E + 00 9.99E − 01 KHCO₃ 1.25E − 04 3.67E − 04 Sulfur Dioxide1.44E − 05 1.09E − 04 K₂CO₃ 7.39E − 07 5.51E − 04 Enzyme 1.18E − 082.37E − 07 Nitrogen 2.92E − 06 6.42E − 06 Nitric Oxide 5.56E − 09 1.96E− 10 Oxygen 1.48E − 06 4.16E − 07 Argon 3.19E − 07 8.97E − 08 NitrogenDioxide 9.09E − 10 2.57E − 10 pH 4.42 7.78

In the same system, it was also determined that if instead of having anabsorption solution bleed stream at the exit of the stripper (where thesolution is CO₂ lean or has a lean loading) one would use the solutionat the entrance of the stripper (where the solution is CO₂ rich or has arich loading), there is no impact on the process water composition andSO₂ removal performance in the quench unit (Table 4). The loadingdefinition is based on the conversion of K₂CO₃ to KHCO₃. A loading of0.0 will mean that all the carbon is under the form of K₂CO₃. A loadingof 0.5, or conversion of 50%, will mean that half the K₂CO₃ has reactedto the KHCO₃ form. A loading of 1.0 will mean that all the carbon ispresent under the KHCO₃ form. This finding indicates that the bleedstream can be taken from various points in the absorption loop, wherethe absorption solution may be rich or lean, for desulfurization.

TABLE 4 Impact of CO₂ loading of the absorption solution bleed on theSO_(x) removal performance Lean Rich Loading Loading 0.4 0.7 QuenchTower Diameter (m) 3.1 3.1 CO₂ removal (%)  0.04  0.00 SO₂ removal (%)86.56 86.56 [K₂CO₃] in solution out quench (mmolL⁻¹)  28.829  28.832Solution temperature out quench (° C.) 45  45  pH of solution in quench7.7 7.7

The SO_(x) removal performance of the quench unit was also evaluated fordifferent scenarios by varying:

-   -   Quench tower height;    -   NO_(x) and SO₂ concentration in the flue gas;    -   Temperature of the solution entering the quench unit;    -   Absorption solution bleed flow rate;    -   Potassium carbonate concentration; and    -   Lean or rich absorption solution used for the bleed.

Example 3: Impact of Quench Tower Height and Pre-Treatment Loop FlowRate (Flow Rate into Quench Unit) on the Performance of the SO₂ RemovalUnit Required for a 100 Tpd CO₂ Capture Plant

To determine how the SO_(x) removal unit performance was impacted byquench tower height and pre-treatment loop flow rate, simulations wereconducted by varying the column height from 2.5 to 15 m and thepre-treatment loop flow rate from 140 to 500 m³/h. The absorptionsolution bleed flow rate was set at 0.092 m³/h (value of Example 1) withthe bleed composition presented in Table 2 for a 17% wt K₂CO₃ absorptionsolution at a temperature of 65° C. The pre-treatment loop flowtemperature was fixed at 30° C. and quench tower was operated at 70%flooding. The flue gas of Table 1 was considered where the NO_(x) andSO₂ concentrations were set at 10 ppmv. The results are shown in FIG. 7and Tables 5-8.

TABLE 5 Quench tower of 2.5 m Pre-treatment loop flow rate (m³ · h⁻¹)140 170 200 230 260 290 350 500 Quench Tower (m) 3.1 3.1 3.2 3.2 3.3 3.33.4 3.5 Diameter CO₂ removal (%) 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04SO₂ removal 55.4 58.9 63.6 67.7 71.3 74.4 79.7 88.19 [K₂CO₃] in solution(mmolL⁻¹) 13.3 13.3 13.4 13.5 13.5 13.5 13.4 12.5 out quench Solutiontemperature (° C.) 69 62 58 54 52 49 46 41 out quench pH solution 7.597.53 7.48 7.45 7.42 7.39 7.36 7.28 inlet quench

TABLE 6 Quench tower of 5 m Pre-treatment loop flow rate (m³ · h⁻¹) 140170 200 230 260 290 350 500 Quench Tower (m) 3.1 3.1 3.2 3.2 3.2 3.3 3.43.5 Diameter CO₂ removal (%) 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04 SO₂removal 80.8 84.6 88.2 91.1 93.3 95.0 97.5 99.9 [K₂CO₃] in solution(mmolL⁻¹) 13.3 13.4 13.4 13.5 13.5 13.5 13.4 13.3 out quench Solutiontemperature (° C.) 69 62 58 54 52 49 46 41 out quench pH solution 7.587.50 7.45 7.41 7.38 7.36 7.32 7.27 inlet quench

TABLE 7 Quench tower of 10 m Pre-treatment loop flow rate (m³ · h⁻¹) 140170 200 230 260 290 350 500 Quench Tower (m) 3.1 3.1 3.2 3.2 3.2 3.3 3.33.5 Diameter CO₂ removal (%) 0.03 0.03 0.04 0.04 0.04 0.04 0.04 0.04 SO₂removal 97.9 99.4 99.9 100 100 100 100 99.95 [K₂CO₃] in solution(mmolL⁻¹) 13.3 13.1 13.4 13.5 13.5 13.4 13.4 13.3 out quench Solutiontemperature (° C.) 69 62 58 54 52 49 46 41 out quench pH solution 7.577.46 7.41 7.37 7.34 7.32 7.29 7.24 inlet quench

TABLE 8 Quench tower of 15 m Pre-treatment loop flow rate (m³ · h⁻¹) 140170 200 230 260 290 350 500 Quench Tower Diameter (m) 3.1 3.1 3.2 3.23.2 3.2 3.3 3.5 CO₂ removal (%) 0.03 0.03 0.04 0.04 0.04 0.04 0.04 0.04SO₂ removal 99.96 99.95 99.95 99.95 99.95 99.95 99.95 99.95 [K₂CO₃] insolution (mmolL⁻¹) 13.3 13.1 13.4 13.5 13.5 13.5 13.4 13.4 out quenchSolution temperature (° C.) 69 62 58 54 51 49 46 41 out quench pHsolution inlet quench 7.56 7.44 7.39 7.35 7.32 7.30 7.27 7.23

The simulations demonstrate that it is possible to remove a significantfraction of the SO₂ present in a flue gas, without removing CO₂, using asolution containing a low K₂CO₃ concentration in the range of 13 mmol/L,this is considerably lower than the absorption solution concentrationwhich is 17% wt or 1.45 M K₂CO₃, corresponding to a 110 dilution factor.

The results also show that the SO_(x) removal is influenced by thepre-treatment loop flow rate and by the quench tower height.

Example 4: Impact of the Concentration of NO_(x) And SO_(x) On the BleedStream Flow Rate for CO₂ Capture Process Equipped with a SO_(x) RemovalUnit. The Absorption Solution in the Absorption Loop is 17% Wt K₂CO₃

The CO₂ capture unit has a 100 tpd capacity and removes 90% of the CO₂of the flue gas. The flue gas composition is found in Table 1. Todetermine the impact of NO_(x) and SO₂ concentrations on the bleedstream flow rate, simulations were conducted considering 85% SO₂ removalusing a 5 m height quench tower operated at 70% flooding, apre-treatment loop flow rate of 200 m³/h, a pre-treatment loop flowtemperature of 30° C. We assumed no NO_(x) removal in the quench towerunder the adopted process conditions. The simulations were run for 2cases: the first case corresponds to a process without SO_(x) removaland the second case when 85% SO_(x) removal is reached. Results areshown in Table 9.

TABLE 9 Influence of impurities on bleed flow rate [column height of 5m; column flooding maintained at 70%; pre-treatment loop flow rate of200 m³h⁻¹; 17 wt % K₂CO₃ absorption solution] Bleed Bleed flow rate flowrate pH K₂CO₃ pre- No pre- SO₂ Pre- Fold solution treatment SO₂ NO_(x)treatment Capture treatment Improvement inlet loop solution (ppmv)(ppmv) (m³h⁻¹) (%) (m³h⁻¹) (—) quench (mmolL⁻¹) 10 10 0.092 86 0.012 87.78 30 10 80 0.092 85 0.050 2 7.78 30 10 150 0.092 84 0.092 1 7.78 3050 10 0.455 86 0.067 7 8.47 138 50 80 0.455 85 0.067 7 8.47 138 50 1500.455 84 0.092 5 8.47 138 100 10 0.910 86 0.142 6 8.64 250 100 80 0.91085 0.142 6 8.64 250 100 150 0.910 84 0.142 6 8.64 250

The above results indicate that when conditions are such that the SO₂concentration and then the SO₄ ²⁻ ion concentration absorbed in solutiondictate the bleed flow rates, there is always an important decrease inthe flow rate of the bleed stream, namely a decrease of at least of5-folds However, when the NO_(x) concentration is high, this results innitrite and nitrate ion concentration levels having a negative impact onthe process performance and then determining the bleed flow rate, thenthe SO_(x) removal unit has no or limited impact. Moreover, it can beobserved, for a fixed NO_(x) concentration, that the bleed flow rate isproportional to the SO_(x) concentration in the flue gas. Additionally,the increase in bleed flow rate increases the K₂CO₃ concentration in theprocess water as well as the pH value. The results on the impact ofSO_(x) removal might be different depending on SO_(x) and NO_(x)relative concentrations in the gas to be treated as it can be seen inthe above Table.

Example 5: Impact of the Concentration of NO_(x) And SO_(x) On the BleedStream Flow Rate for CO₂ Capture Process Equipped with a SO_(x) RemovalUnit. The Absorption Solution in the Absorption Loop is 45% Wt K₂CO₃

The CO₂ capture unit has a 100 tpd capacity and removes 90% of the CO₂of the flue gas. The flue gas composition is found in Table 1. Todetermine the impact of NO_(x) and SO₂ concentrations on the bleedstream flow rate, simulations were conducted considering using samesimulation conditions as Example 4. The conditions are: a 5 m heightquench tower operated at 70% flooding, a pre-treatment loop flow rate of200 m³/h, pre-treatment loop flow temperature of 30° C. We assumed noNO_(x) removal in the quench tower under the adopted process conditions.The simulations were run for 2 cases: the first case corresponds to aprocess without SO_(x) removal and the second case with SO_(x) removal.The percentage of SO₂ removal was evaluated for each case. Results areshown in Table 10.

TABLE 10 Influence of impurities on bleed rate [column height of 5 m;column flooding maintained at 70%; pre-treatment flow rate of 200 m³h⁻¹;45 wt % K₂CO₃ absorption solution] Bleed flow Bleed rate flow rate K₂CO₃No pre- SO_(x) Pre- Fold in process SO₂ NO_(x) Treatment CaptureTreatment Improvement water (ppmv) (ppmv) (m³h⁻¹) (%) (m³h⁻¹) (—) pH(mmolL⁻¹) 10 10 0.092 96 0.006 14 8.44 100 10 80 0.092 96 0.050 2 8.44100 10 150 0.092 96 0.092 1 8.44 100 50 10 0.455 91 0.042 11 8.70 437 5080 0.455 91 0.050 9 8.70 437 50 150 0.455 91 0.092 5 8.70 437 100 100.910 89 0.101 9 8.87 693 100 80 0.910 89 0.101 9 8.87 693 100 150 0.91089 0.101 9 8.87 693

The above results indicate that when conditions are such that the SO₂concentration and then the SO₄ ²⁻ ion concentration absorbed in solutiondictate the bleed flow rates, there is always an important decrease inthe flow rate of the bleed stream, namely a decrease of at least 80%.However, when the NO_(x) concentration is high this results in nitriteand nitrate ion concentrations having a negative impact on the processperformance and then having an impact on the bleed flow rate, then theSO_(x) removal unit has no or limited impact. Moreover, it can beobserved, for a fixed NO_(x) concentration, that the bleed flow rate isproportional to the SO_(x) concentration in the flue gas. Additionally,the increase in solvent flow rate increases the K₂CO₃ concentration inthe process water as well as the pH value. The results on the impact ofSO_(x) removal might be different depending on SO_(x) and NO_(x)relative concentrations in the gas to be treated as it can be seen inthe above Table.

Example 6: Impact of Pre-Treatment Flow Temperature on SO_(x) RemovalRate and Bleed Flow Rates

Simulations were conducted for a 100 tpd CO₂ capture unit combined witha SO_(x) removal unit in the pre-treatment loop. For the purpose of thesimulations the height of the quench tower was 5 m, column flooding wasmaintained at 70% flooding, pre-treatment flow rate was 200 m³/h, SO₂concentration was 10 ppmv, the absorption solution for the absorptionloop was 1.45 M K₂CO₃ or 17% wt K₂CO₃.

The results indicate that additional benefits can be obtained byoperating the pre-treatment loop at higher temperatures (FIG. 8). Byincreasing the pre-treatment loop flow temperature from 30 to 60° C.,the SO₂ removal can be increased from 85 to 100% while the bleed flowrate would be decreased from 0.012 down to 0.006 m³/h. Therefore, theSO_(x) removal pre-treatment may still be integrated in a process wherethe gas temperature entering the absorber would be higher than 30° C.

The invention claimed is:
 1. A process for removing CO₂ from a gas comprising at least water vapor, CO₂ and SO_(x), where x is equal to 2 and/or 3, the gas having an initial gas temperature, the process comprising a pre-treatment loop for desulfurizing the gas and recovering a SO_(x)-depleted gas, and an absorption loop for removing CO₂ from the SO_(x) depleted gas, wherein the process comprises cooling an alkaline aqueous solution comprising water and a carbonate and bicarbonate of an alkali metal to obtain a cooled alkaline aqueous solution having a temperature lower than the initial gas temperature; contacting the gas with the cooled alkaline aqueous solution in a desulfurization unit of the pre-treatment loop, thereby causing cooling of the gas, condensation of some water vapor and absorption of the Sox in the cooled alkaline aqueous solution, and producing the SO_(x) depleted gas and an acidic aqueous solution comprising sulfate and/or sulfite ions; purging a first portion of the acidic aqueous solution exiting the desulfurization unit; supplying the SO_(x) depleted gas which contains CO₂ from the desulfurization unit to a CO₂ capture unit of the absorption loop; in the CO₂ capture unit, contacting the SO_(x) depleted gas with an absorption solution comprising water and carbonate of the alkali metal, thereby causing absorption of the CO₂ in the absorption solution and producing a CO₂-depleted gas and a carbonate and bicarbonate-rich absorption solution; treating the carbonate and bicarbonate-rich absorption solution in a stripping unit to generate a purified CO₂ gas and recover a carbonate and bicarbonate-lean absorption solution; bleeding a fraction of an absorption solution circulating in the absorption loop (e.g., from the carbonate and bicarbonate-lean absorption solution or from the carbonate and bicarbonate-rich absorption solution) as an absorption solution bleed; and mixing the absorption solution bleed with a second portion of the acidic aqueous solution exiting the desulfurization unit of the pre-treatment loop to produce the alkaline aqueous solution.
 2. The process of claim 1, wherein the gas contacted with the cooled alkaline aqueous solution has a concentration in SO_(X) of from 1 to 100 ppmv.
 3. The process of claim 1, wherein the gas is a flue gas.
 4. The process of claim 1, wherein the gas is a post-combustion flue gas.
 5. The process of claim 1, wherein the temperature of the cooled alkaline aqueous solution is from about 5° C. to about 60° C.
 6. The process of claim 1, wherein the cooled alkaline aqueous solution has a concentration in carbonate of the alkali metal of from about 1 mM to about 1 M.
 7. The process of claim 1, wherein the cooled alkaline aqueous solution has a pH from 7 to 9.5.
 8. The process of claim 1, wherein the desulfurization unit comprises a contacting device selected from a bubble column, a packed column with random packing, a packed column with structured packing, a venturi, a barometric leg, an eductor, a spraying device or a demister pad.
 9. The process of claim 1, wherein the desulfurization unit comprises a packed column with random packing, a packed column with structured packing, or a spraying device.
 10. The process of claim 1, wherein contacting the gas with the cooled alkaline aqueous solution is performed under conditions to produce a SO_(X) depleted gas in which at least 50% of the SO_(X) has been removed.
 11. The process of claim 1, further comprising removing solid particles from the acidic aqueous solution.
 12. The process of claim 1, further comprising removing solid particles from the acidic aqueous solution using a separation system selected from a radial vane separator, a Schoepentoeter device, a cyclone, a settling system or a filtration unit.
 13. The process of claim 1, wherein the purging is performed to maintain a mass balance in the pre-treatment loop.
 14. The process of claim 1, wherein the purging is performed at a flowrate determined by a water vapor condensation rate and an absorption solution bleed flowrate.
 15. The process of claim 1, wherein the gas contacted with the cooled alkaline aqueous solution further comprises NO_(x′) where x′ is equal to 1 and/or
 2. 16. The process of claim 15, wherein the NO_(x′) are present in the gas in a concentration of from 10 to 150 ppmv.
 17. The process of claim 15, further comprising adjusting a flow rate of the absorption solution bleed to maintain a concentration of nitrite and nitrate ions in the absorption loop for optimal CO₂ capture.
 18. The process of claim 1, wherein contacting the SO_(x)-depleted gas with the absorption solution in the CO₂ capture unit is performed in the presence of a carbonic anhydrase or an analogue thereof.
 19. The process of claim 18, wherein the carbonic anhydrase or analogue thereof is present in the absorption solution.
 20. The process of claim 19, wherein the carbonic anhydrase or analogue thereof is in a concentration below 0.1% by weight of the absorption solution.
 21. The process of claim 1, wherein the absorption solution in the CO₂ capture unit has a concentration of from 1 to 5 mol L⁻¹.
 22. The process of claim 1, wherein the alkali metal is potassium or sodium. 